An analyst field trip presentation from April 2015 for Memorial Resource Development Corporation. The presentation shows the geology and details of MRD's drilling in the Terryville Field area of the Cotton Valley Tight Gas play in northern Louisiana. MRD entered into a deal in May 2016 to be bought by Range Resources, a Marcellus Shale producer.

1. Analyst Field Trip Presentation
Shreveport, Louisiana

2. 2
Forward-Looking Statements
This presentation includes "forward-looking statements" within the meaning of Section 27A of the Securities Act of 1933, as amended,
and Section 21E of the Securities Exchange Act of 1934, as amended. Forward-looking statements can be identified by terminology
such as “may,” “will,” “could,” “should,” “expect,” “plan,” “project,” “forecast,” “intend,” “anticipate,” “believe,” “estimate,” “predict,”
“potential,” “pursue,” “target,” “outlook,” “continue,” the negative of such terms or other comparable terminology. All statements, other
than historical facts included in this presentation, that address activities, events or developments that Memorial Resource Development
Corp. (MRD) expects or anticipates will or may occur in the future and such things as MRD’s future capital expenditures (including the
amount and nature thereof), business strategy and measures to implement strategy, competitive strengths, goals, expansion and growth
of MRD’s business and operations, plans, market conditions, references to future success, references to intentions as to future matters
and other such matters are forward-looking statements. All forward-looking statements speak only as of the date of this presentation.
Although MRD believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are
reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results
could materially differ from what is expressed, implied or forecast in such statements.
MRD cautions you that these forward-looking statements are subject to risks and uncertainties, most of which are difficult to predict and
many of which are beyond MRD’s control, incident to the exploration for and development, production, gathering and sale of natural gas
and oil. These risks include, but are not limited to: commodity price volatility; inflation; lack of availability of drilling and production
equipment and services; environmental risks; drilling and other operating risks; regulatory changes; the uncertainty inherent in
estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital; and the timing of
development expenditures. Information concerning these and other factors can be found in MRD’s filings with the Securities and
Exchange Commission, including its Forms 10-K, 10-Q and 8-K. Consequently, all of the forward-looking statements made in this
presentation are qualified by these cautionary statements and there can be no assurances that the actual results or developments
anticipated by MRD will be realized, or even if realized, that they will have the expected consequences to or effects on MRD, its
business or operations. MRD has no intention, and disclaims any obligation, to update or revise any forward-looking statements,
whether as a result of new information, future results or otherwise.
Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels.
2

3. 3
Agenda
• John A. Weinzierl – Chief Executive Officer
Executive
Summary
• Larry R. Forney – Senior VP, Chief Operating Officer
Operational
Overview
• Kyle McQuire – Staff GeologistGeology
• Andrew J. Cozby – Senior VP, Chief Financial Officer
Financial
Overview
• John Williams – Director, Reservoir EngineeringReserves
• William J. Scarff – PresidentIntroduction

4. 4
Executive Summary

5. 5
The Premier Horizontal E&P Company
• Consolidated core position in the Terryville Complex of North Louisiana
• Top tier returns – projected single well IRRs of >200% at current commodity prices(1)
• High quality, repeatable stacked pays
• Conventional, tight gas reservoir provides predictable returns
Prolific
Asset Base
• >1,600 horizontal drilling locations in four primary zones (35+ years of inventory)
– ~22 year drilling inventory inside of NSAI’s 3P acreage
• Continue to increase already dominant acreage position in North Louisiana
– 68,032 net acres in the Terryville Complex – up 32% since IPO(2)
• Additional over-pressurized, liquids-rich opportunities in North Louisiana
Significant
Upside Potential
• First-in-class expertise in the over-pressured liquids rich Cotton Valley
• Exceptional track record with horizontal development and completion
• Commitment to safety and environmental stewardship
• Public company experience with highly incentivized management
Focused
Management Team
• Significant liquidity and low leverage
• Expect to fund growth predominately with internally generated cash flow
• Expect continued reduction in per unit costs
• Industry-leading hedge position
Best-In-Class
Financial Metrics
(1) See Appendix for information on our IRR calculation
(2) Includes the effect to the asset swap with MEMP completed in February 2015

6. 6 Proved Possible Probable
Terryville Field Pure-Play
Reserves Breakdown (1) Asset Overview
3P PV-10 By Category
$6.2 billion
1P By Commodity
1P By Category
1.4 Tcfe
(1) As of April 1, 2015. Gives effect to the asset swap with MEMP completed in February 2015 and does
not include MRD’s Rockies properties
(2) Proved, probable and possible reserves audited by Netherland, Sewell & Associates, Inc. (NSAI); report
based on SEC pricing as of 12/31/14. Reserves and production are pro forma for the asset swap with
MEMP completed in February 2015. See “Cautionary Statements and Additional Disclosures” in the
Appendix for more information regarding 3P reserves and PV-10
$1.1BN
$2.8BN
$2.3BN
Gas
NGL
PUD32%
3%
65%
PDP PDNP PUD
72%
23%
5%
Gas NGL Oil
Key Statistics
Terryville
Complex Other
Total MRD
Louisiana
Gross Acres(1)
81,012 27,772 108,784
Net Acres(1)
68,032 25,300 93,332
Proved Reserves (Bcfe)(2)
1,367 18 1,385
% Gas Reserves 72% 82% 72%
Q4 Production (MMcfe/d)(2)
256 4 260
Proved Reserve Life (R/P) 14.6 11.0 14.6

7. 7
High Production Rates Throughout Cotton Valley Trend
MRD has the Top 23 Wells in the Cotton Valley Trend
M.T. Peyton 12H – 19.8 MMcfe/d
Crenshaw 14H – 19.3 MMcfe/d
Neal 12H – 18.0 MMcfe/d
G Breffeilh 11 H – 11.1 MMcfe/d
Berry Etal 24H – 11.1 MMcfe/d
Walton 23H – 10.6 MMcfe/d
Gail King 25H – 16.6 MMcfe/d
Fullen GU 11H – 14.5 MMcfe/d
Fullen GU 4H – 13.9 MMcfe/d
Hutchinson 9-005 – 14.9 MMcfe/d
Killen 13 003-Alt – 13.1 MMcfe/d
Elm Grove Pltn. 063-Alt – 12.6 MMcfe/d
Terryville Complex
Dowling 19-30 HC-2 – 31.6 MMcfe/d
DL Sanford 18-7 – 30.5 MMcfe/d
Wright 13 24 HC-3 – 30.3 MMcfe/d
Dowling 19-30 HC-1 – 28.4 MMcfe/d
Colvin Estate 28-33 4 HC-1 – 26.2 MMcfe/d
Henderson Field
Crow Holland 2H 14-603 – 17.3 MMcfe/d
Roger King 1H – 15.3 MMcfe/d
Pone 7H – 14.9 MMcfe/d
South Carthage
Ritter 4H – 16.7 MMcfe/d
Joaquin
May 5H – 13.2 MMcfe/d
Wiener Estate F2H – 12.1 MMcfe/d
Lloyd 5-6H – 11.3 MMcfe/d
Rogers 6H – 11.3 MMcfe/d
• 23 Active Cotton Valley Horizontal Rigs across +250 miles
Sources: HPDI and Company data. MRD production rates include NGLs post-processing, all other operators based on reported peak monthly production.

8. 8
0%
0%
1%
2%
11%
13%
43%
0% 10% 20% 30% 40% 50%
Devon
CHK
EQT
Chief
EnCana
Cabot
MRD
Completion IP-30
Date Well Name (MMcfe/d) Target Percentile
Nov-14 Dowling 19-30 HC-2 31.6 Upper Red 0.0%
Nov-14 DL Sanford 18-7 30.5 Upper Red 0.0%
Apr-14 Wright 13 24 HC-3 30.3 Upper Red 0.0%
Nov-14 Dowling 19-30 HC-1 28.4 Upper Red 0.0%
Oct-14 Colvin Estate 28-33 4 HC-1 26.2 Upper Red 0.1%
Aug-14 Werner 29 32 5 HC-2 26.1 Upper Red 0.1%
May-14 Wright 13 24 HC-4 25.7 Lower Red 0.1%
Apr-14 LA Minerals 19 30 HC-2 25.1 Upper Red 0.1%
Apr-14 Wright 13 24 HC-1 25.0 Upper Red 0.1%
Oct-14 Colvin Estate 28-33 4 HC-2 23.9 Upper Red 0.1%
Apr-14 TL McCrary 14 11 HC-5 22.9 Upper Red 0.2%
Dec-13 Wright 13 12 HC-2 22.7 Upper Red 0.2%
Nov-14 James R Dowling 30-31 HC-1 22.5 Upper Red 0.2%
Jun-14 Drewett 17 8H-1 22.1 Upper Red 0.2%
Nov-13 LA Minerals 19 30 HC-1 21.5 Upper Red 0.2%
Nov-12 Nobles 13H-1 21.5 Upper Red 0.3%
Dec-14 Daniels 17 8 H-1 19.9 Upper Red 0.4%
Aug-14 Wright 14 11 HC-1 19.6 Upper Red 0.4%
Nov-14 TL McCrary 14 23 26 HC-1 19.6 Lower Red 0.4%
May-13 Werner 29 32 5 HC-1 18.4 Upper Red 0.5%
Jul-12 LA Minerals 15 22H-2 17.8 Upper Red 0.5%
Jan-14 Colquitt 20 17H-1 17.5 Upper Red 0.5%
Jan-13 Sidney McCullin 16 21H-1 17.4 Upper Red 0.5%
Sep-12 Dowling 22 15H-1 16.3 Upper Red 0.7%
Dec-13 Nobles 13H-2 16.0 Lower Red 0.8%
Dec-14 Wright 13-24 HC-5 15.8 Lower Red 0.8%
Nov-12 Dowling 20 17H-1 15.2 Upper Red 0.9%
Dec-14 Wright 13-12 HC-5 15.0 Upper Red 1.0%
Aug-14 BF Fallin 22 15H-1 14.8 Upper Red 1.0%
Cabot
35
MRD
23
Chesapeake
6
EnCana
6
Devon
4
EQT
4
Chief
3
Other
19
World Class Asset Productivity
MRD Has Top Productive Wells
• Since 2012, 47 wells of >17,000 horizontal gas wells in
the U.S. have peak monthly production over 21 MMcfe/d
– 16 of those were drilled by Memorial
• Memorial has drilled 37 wells in the top 2% of the 17,000
horizontal wells (29 wells in the top 1%)
Source: HPDI and MRD data
Note: MRD data shown includes NGLs after processing; all other well results based on data as reported per HPDI. MRD using estimated shrink and NGL yields for
recent horizontal wells. Well percentile based on peak 30-day Mcfe production for over 17,000 horizontal gas wells in the U.S. drilled since 2012. Assuming
company data before processing, MRD would have 20 wells in the top 100, representing 38% of MRD’s wells in the top 100 wells drilled since 2012
Top 100 Gas Wells by Operator
Percentage of Operator’s Total Wells in Top 100
Peak 30-Day Mcfe Production
Marcellus
Cotton Valley
Marcellus

9. 9
Q1'12 Q2'12 Q3'12 Q4'12 Q1'13 Q2'13 Q3'13 Q4'13 Q1'14 Q2'14 Q3'14 Q4'14
Vertical Terryville Horizontal Terryville
14.6
17.2
15.2
16.7 15.8
21.6
18.7
21.2
Q1'13 Q2'13 Q3'13 Q4'13 Q1'14 Q2'14 Q3'14 Q4'14
Best-in-Class Performance and Economics
Exceptional Horizontal Well Results in Four Primary Zones(1)
• Highly prolific and liquids-rich production characteristics
• Top-tier cost structure
• Rapidly accelerating drilling program in the Terryville Complex
– Started 2013 with 2 rigs, currently running 8 rigs
High IRRs at Current Prices(2)
20
(1) Excludes three delineation wells: Drewett 17 8H-2, Gleason 31H-1 and Burnett 26H-1
(2) Terryville IRRs based on MRD internal estimates with additional IRRs from Credit Suisse Equity Research. IRRs are based on a flat crude oil price of $50.00 per
barrel and a natural gas price of $2.90, $3.18, $3.42, $3.52, $3.59, and $3.69 per MMBtu for years one through six respectively and held flat thereafter. See
Appendix for more information on our IRR calculation.
(3) Includes only Terryville Field and gives effect to the asset swap with MEMP completed in February 2015
Q1 2012 Prod.
39 MMcfe/d(3)
Q4 2014 Prod.
256 MMcfe/d(3)
• Further upside to drilling economics as we
transition to pad drilling with longer laterals
and potential cost reductions
2013 2014
Avg. 17.7 MMcfe/d
Average IP-30
per Quarter
(MMcfe/d)
73%
44%
20%
17%
17%
13%
12%
12%
6%
5%
172%

10. 10
Terryville Field – Strong Horizontal Well Results (Unhedged)(1)
$80 oil / $4.00 gas $70 oil / $3.50 gas $60 oil / $3.00 gas
IRR%
$50 oil / $2.50 gas
MRD’s drilling inventory projected to be highly economic across all commodity price environments
Source: MRD internal type curve estimates
(1) Assumes 7,500 foot lateral length; 100% working interest / 78% net revenue interest; and well cost of ~$11.8MM; see Appendix for more
information on our IRR calculation
~75% of MRD 2015 Capex Directed to Upper Red Target
$35.1
$20.6
$13.4
$28.6
$16.1
$9.9
$22.1
$11.6
$6.4
$15.5
$7.0
$2.9
+200% +200%
139%
+200%
145%
86%
+200%
86%
50%
121%
47%
25%
0%
40%
80%
120%
160%
200%
$0
$4
$8
$12
$16
$20
$24
$28
$32
$36
$40
NPV10
($MM)

11. 11
Transitioned to Pure-Play Story(1)
• MRD received:
– All of MEMP’s position in the Terryville Field
– Cash consideration of $78 million
• MEMP received:
– Primarily properties located in the Joaquin Field in
Shelby and Panola counties in East Texas
– Other “non-core” assets in East Texas and West
Louisiana
• Effective date of January 1, 2015
– MRD will not receive any production from the
divested assets nor be liable for any associated
capex in 2015
MRD / MEMP Transaction Overview
Strategic Rationale
• Transitions MRD into a pure-play Terryville
Field E&P company
• High-grades capital program to higher
returning Terryville assets
• Increases average working interest for 2015
drilling program to ~91%
• Increases percentage of expected 2015
production hedged to ~78%(2)
(1) Gives effect to the asset swap with MEMP completed in February 2015
(2) Using the mid-point of MRD's guidance range announced on February 24, 2015
(3) YE 2014 reserves and 4Q 2014 production are pro forma for the asset swap with MEMP completed in February 2015
Terryville
99%
Outside
1%
YE
2014
Terryville
79%
Outside
21%
At IPO
Terryville
98%
Outside
2%
4Q
2014
Proved Reserves
Terryville
84%
Outside
16%
At IPO
Production
At IPO (Bcf)
Terryville Complex 945
Outside 181
Total 1,126
Current (Bcf) (3)
Terryville Complex 1,367
Outside 18
Total 1,385
At IPO (MMcfe/d)
Terryville Complex 141
Outside 38
Total 179
Current (MMcfe/d) (3)
Terryville Complex 256
Outside 4
Total 260

12. 12
Multi-Year Drilling Inventory Drives Upside Potential
Terryville Horizontal Locations by Pay-Zone(1)(2)
• Multi-zone exploration opportunities which
are being steadily delineated by MRD
• 1,648 identified potential drilling locations in
four primary zones support substantial net
asset value
• Additional 285 locations in Other Zones per
NSAI, not including additional locations
identified by Management
• NSAI audited 3P Terryville future locations
of 856 at YE 2014 significantly increased
from 688 at YE 2013
• NSAI audited 3P PV-10 of $6.2 billion at YE
2014 and 4.7 Tcfe of 3P reserves(3)
(1) Does not include 35 NSAI 3P locations in the Rockies
(2) Schedule includes 285 locations in Other Zones per NSAI. Other Zones category does not include additional management locations
(3) Proved, probable and possible reserves audited by NSAI; report based on SEC pricing as of 12/31/14. Reserves are pro forma for the asset swap with
MEMP completed in February 2015. See “Cautionary Statements and Additional Disclosures” in the Appendix for more information regarding 3P reserves,
PV-10 and management locations
Terryville Locations(1)
1,648
in NSAI
3P
Acreage
Upper Red Lower Red Lower
Deep Pink
Upper Deep
Pink
Other Zones Total
MRD
175
243
418
153
271
424 94
309
403 149
254
403
285
1,237
696
1,933
= Management Locations= NSAI Locations
35+ year drilling inventory in
four primary zones under
current drilling program
Zone Proved Prob. Poss. NSAI 3P Mgmt Total
Upper Red 81 41 53 175 243 418
Lower Red 52 48 53 153 271 424
Lower Deep Pink 8 30 56 94 309 403
Upper Deep Pink - 93 56 149 254 403
Total Four Primary Zones 141 212 218 571 1,077 1,648
Other Zones - - 285 285 - 285
Total MRD 141 212 503 856 1,077 1,933
PV-10 ($ billion) - - - $6.2 - -
Years of Inventory - - - 20 - 45

13. 13
Operational Overview

14. 14
• Large number of service providers in a historically active oil & gas region
• Favorable regulatory environment
• Rural environment reduces relative development concerns
• Extensive midstream infrastructure provides ample takeaway capacity compared
to other producing regions
• Low product differentials due to proximity to the Gulf Coast
Superior
Operating
Environment
Terryville Field – World Class Asset
• Large, conventional tight gas reservoir best exploited through horizontal drilling
• Elevated pore pressure (~0.8 psi/ft) creates prolific original gas in place
• High reservoir energy plus quality rock yields superior production rates and EURs
• High liquids yield improves economics
• Stacked reservoirs with 4 over pressured Lower Cotton Valley zones and
9 normally pressured Upper Cotton Valley zones
Excellent
Reservoir Quality
• High IP rate wells
• Industry leading EURs
• Rapid payouts with projected rates of return of >200%
• Multi-year inventory
• Highly prolific liquids-rich production characteristics
Best-in-Class
Economics

15. 15
CottonValley–NormallyPressuredLowerCottonValley–Overpressured
(Taylor)
(Sexton)
(Roseberry)
(Justiss)
Green
(Davis)
Vaughn
~8,500’
~11,500’
Horizontal Drilling Unlocks Full Potential
Legacy Vertical Production Focused on Commingling Sections, Horizontal Development Focused on Specific Zones
CV Stacked Horizontal TargetsLegacy Vertical Development
Discovery –
Late ‘50’s
Late ‘70’s –
Mid ‘80’s
2
3
1
37
14
1
Competitor
Activity
2002 – 2008
Production Wells Since 2012(1)
Discovery –
Late ‘50’s
(1) As of March 31, 2015

16. 16
0
2,000
4,000
6,000
8,000
10,000
12,000
0
50,000
100,000
150,000
200,000
250,000
300,000
350,000
400,000
450,000
Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14
Oil/Condensate(Bbl/d)
WetGas(Mcf/d)
Wet Gas Oil / Condensate Well Count
Significant Production Growth From Horizontal Wells
April 2006:
Petrohawk acquires
Terryville Field from KCS
May 2010:
MRD acquires Terryville
Field from Petrohawk
Total of 41
producing vertical wells
Horizontal redevelopment
increases Terryville gross
production by 11x from 53 wells(1)
Total of 181
producing vertical wells
Gross Terryville Field Production(1)
(1) As of December 31, 2014

17. 17
Polygon
3P
Polygon
2P
Polygon
1P
Lincoln
Claiborne
Jackson
Bienville
20N 4W20N 5W 20N 3W
19N 5W
19N 4W
19N 3W
18N 5W 18N 4W 18N 3W
17N 5W 17N 4W 17N 3W
2015 MRD Development Plan
Pad Name
First
Production # Wells Zone(1)
2014 NSAI
Res. Category
Colvin Estate Q4’14 2 2 UR Proved
D L Sanford Q4’14 1 1 UR Proved
Dowling Q4’14 2 2 UR Proved
TL McCrary Q4’14 1 1 LR Proved
James R.
Dowling
Q4’14 1 1 UR Proved
Wright Q4’14 2 1 LR, 1 UR Proved
Daniels Q4’14 1 1 UR Proved
Drewett Q4’14 1 1 UR Proved
LMO 1H’15 1 1 UR
Probable
Possible
Davison 1H’15 2 2 UR Proved
Drewett 1H’15 1 1 UR Proved
Aulds 1H’15 1 1 UR Proved
Dowling 1H’15 3 3 UR Proved
Dunn Estate 2H’15 2 2 UR Proved
Dowling 2H’15 1 1 UR Proved
Wright 2H’15 4 2 UR, 2 LR Proved
TL McCrary 2H’15 4
2 UR, 1 LR
1 UDP
Proved
Hearne 2H’15 4 3 UR, 1 LR Proved
Temple 2H’15 2 2 UR Proved
Brazzel 2H’15 4 4 UR Proved
Belleview Timber 2H’15 2 2 UR Proved
Lewis 2H’15 4 2 UR, 2 LR Proved
Wallace 2H’15 3 2 UR, 1 LR Proved
Drewett 2H’15 3 1 UR, 2 LR Proved
TL McCrary 2H’15 3 1 UR, 2 LR Proved
P1
P2
3
4
5
6
7
8
9
10
11
12
P3
P4
13
P5
P6
14
15
P7
P8
16
Legend
2014 Wells
2015 Wells
P1
5
P3
P5
P4
P2
6
3
P6
4
P7
P8
17
P1
7
8
9
10
11
12
13
14
15
16 P2
P1
P2
17
(1) UR = Upper Red, LR = Lower Red, UDP = Upper Deep Pink, LDP = Lower Deep Pink
MRD Acreage
Horizontal Well
Vertical Well
Proved
Probable
Possible

18. 18
Louisiana Methodist Orphanage (“LMO”)
Louisiana Methodist Orphanage YE 2013 Reserves Map
• Summary
– Target: Upper Red
– Lateral length: 6,150 feet
– IP-30: 3.7 MMcfe/d
• Limited geological control from
existing vertical and horizontal
wells
– Drilled pilot hole and collected
wireline logs and sidewall cores
LMO Represents a Sizable Step-Out Well Located Outside of NSAI 3P Acreage When Drilled
Polygon
1P
Polygon
2P
19N 5W
19N 4W
19N 3W
18N 5W 18N 4W 18N 3W
17N 5W 17N 4W 17N 3W
Claiborne
Bienville
Jackson
Lincoln
F
0
LMO 2-11 HC #1
MRD Acreage
Horizontal Well
Vertical Well
Proved
Probable
Possible
~18 Miles

19. 19
LMO Results Confirm Reservoir Quality
• Verified over-pressured nature of the reservoir
˗ Pressure gradient consistent with balance of the field
• Confirmed hydrocarbons across all four Lower Cotton Valley
zones at some of the deepest depths drilled to date in the field
˗ Second deepest structural test in Lower Cotton Valley at Terryville
Field
˗ Have not located outer boundaries of Terryville Field
• Comparable sand development and petrophysical
characteristics to the 2-well Dowling Pad and Burnett well
˗ Dowling 19 30 HC 2-well pad achieved IP-30 of 60.0 MMcfe/d
˗ Burnett 26H-1 well achieved IP-30 of 6.9 MMcfe/d with a 2,405’
lateral (~21.6 MMcfe/d normalized to 7,500’ lateral)
Encouraging Results YE 2014 Reserves Map
Cross Section from Dowling to LMO Shows Continuous and Consistent Sand Development Across the Field
~5 Miles
A’A
UPPER
DEEP
PINK
LOWER
DEEP
PINK
UPPER
RED
LOWER
RED
Polygon
3P
Polygon
2P
Polygon
1P
19N 5W
19N 4W
19N 3W
18N 5W 18N 4W 18N 3W
17N 5W 17N 4W 17N 3W
Claiborne
Bienville
Jackson
Lincoln
F
0
A A’

20. 20
Polygon
3P
Polygon
2P
Polygon
1P
19N 5W
19N 4W
19N 3W
18N 5W 18N 4W 18N 3W
17N 5W 17N 4W 17N 3W
Claiborne
Bienville
Jackson
Lincoln
F
0
LMO Geology – Comparable Rock Quality Across the Field
Microscopic Core Images LMO Geo-Steering Cross Section – Only ~60% of lateral drilled in target porosity zone
LMO Upper Red Microscopic Image
BF Fallin Upper Red Microscopic Image
• Log data support comparable petrophysical (e.g. porosity) and depositional
characteristics (e.g. sand bedding) to the balance of the developed field area
• Microscopic images and lab analysis of LMO core data support similar rock
composition (e.g. grain size and matrix framework) to the balance of the
developed field area
‒ White quartz grains that interact with clay minerals preserved porosity as
the reservoir was buried
• MRD has proven track record of improving performance on follow-up
development around step-out wells across the field
White
Quartz
Grains
Dark
Clay
Burrows
25
~6,150 feet
LMO Reservoir Data Consistent with Previous Successful Horizontal Completions
Gamma
Ray
Gas
Data
Out-Of-Zone

21. 21
Polygon
3P
Polygon
2P
Polygon
1P
19N 5W
19N 4W
19N 3W
18N 5W 18N 4W 18N 3W
17N 5W 17N 4W 17N 3W
Claiborne
Bienville
Jackson
Lincoln
0
MRD Acreage
Horizontal Well
Vertical Well
Proved
Probable
Possible
Expanded Activity Following the LMO Step-Out Well (1)
MRD’s Future Development Continuing South Based on Encouraging Results of the LMO
Initial step out well
Follow-up well area
Expanded activity area
2015 Follow-Up Activity
• Added Dowling well ~1.5 mi.
northwest of LMO, expected
production 2H’15
• TD’d the Aulds well ~2.75
mi. northeast of LMO,
expected production 1H’15
• 2 well Temple pad ~3 mi.
East of LMO, expected
production 2H’15
• Permitting Temple South
offset well
• Permitting and lease activity
in preparation for future
development
(1) Map includes all existing wells on production as of 12/31/14 and the 2015 Development Plan wells
2016 Follow-Up Activity
• 3 wells ~1.5 mi. to the
northeast of the LMO,
production expected 1H’16
• 4 wells ~1.5 mi. to the
northwest of the LMO,
production expected 1H’16
• Further development with
immediate offsets
LMO
• LMO initial production 1Q’15
• Verified over-pressured
formations
• Confirmed target zones at
2nd deepest depths of
Terryville Field
• Confirmed reservoir quality

22. 22
Polygon
3P
Polygon
2P
Polygon
1P
19N 5W
19N 4W
19N 3W
18N 5W 18N 4W 18N 3W
17N 5W 17N 4W 17N 3W
Claiborne
Bienville
Jackson
Lincoln
0
MRD Acreage
Horizontal Well
Vertical Well
Proved
Probable
Possible
Proven Track Record with Step-Out Wells(1)
Follow-up Wells Consistently Outperforming Initial Step-Out Wells
Initial step out well
Follow-up well area
Expanded activity area
East Step-Out
• Temple and Werner pads
completed in mid-2014
˗ Avg. IP-30: 14.1 MMcfe/d
• 2-well Colvin Estates pad
completed in late 2014
˗ Avg. IP-30: 25.1 MMcfe/d
• James R. Dowling well
completed in late 2014
˗ IP-30: 22.5 MMcfe/d
• 11 additional wells expected
to be brought online in 2015
(1) Map includes all existing wells on production as of 12/31/14 and the 2015 Development Plan wells
Northwest Step-Out
• Colquitt well completed in late 2012
˗ IP-30: 17.5 MMcfe/d
˗ Spurred further development
throughout the field
• Sanford, Daniels and Drewett wells
completed in 2014
˗ Avg. IP-30: 20.5 MMcfe/d
˗ Further proved-up the region
• 13 additional wells expected to be
brought online in 2015
West Step-Out
• Gleason well drilled in late 2013
˗ IP-30: 2.9 MMcfe/d
• 2 Dowling wells completed in late
2014
˗ Avg. IP-30: 30.0 MMcfe/d
• 3 additional wells expected to be
completed in surrounding area
during 2015

23. 23
Rig Day Rates
24%
Other
29%Directional
10%
Mud
8%
Rentals
9%
Location
4%
Casing
16%
Potential D&C Capex Reductions
Drilling – AFE Break-Down by Category Total D&C
Completions – AFE Break-Down by Category
• Aggressively pursuing cost savings across all
cost categories
• Anticipate reductions in largest cost categories
• Expect to realize the majority of savings in
second half of 2015
• Drilling
– Rig day rates constitute ~24% of total drilling costs
– Majority of drilling contracts unwinding April -
October 2015
– Negotiating early reductions of existing rates
– Anticipate 20%-30% cost reductions in rig day rates
– Anticipate 20%-30% cost reductions in directional
tools and services
– Anticipate 5%-10% cost reductions in casing
• Completions
– Frac pumping services constitute ~57% of total
completion costs
– No contract commitments on frac services, so
currently realizing cost reductions through bidding
process
– Anticipate 20%-30% cost reductions in frac pumping
services and materials
– Anticipate 10%-25% cost reductions in electric line,
perf, coiled tubing, well testing
(1) “Other“ is inclusive of mobilization / demobilization, fuel, power, water, consulting service / supervision, cement services and additional items
(2) “Other“ is inclusive of production facilities, wellhead equipment, tubing, surface rentals and additional items
(1)
Frac Pumping
Services &
Materials
57%
Other
22%
Electric Line, Perf,
Coiled Tubing, Well
Testing
14%
Fuel and Frac
Water
7%
(2)

24. 24
Continued Operational Performance Improvement
4,428 4,468
5,870
7,088
6
15
31
43
16.7
14.0
19.7
0
5
10
15
20
25
30
35
40
45
50
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
2012 2013 2014 2015 Budget
Feet
Average Lateral Length (Feet)
Wells on First Sales
Average IP-30 per Well (Mmcfe/d)
Increasing Lateral Lengths
$150
$81 $78
$65
$0
$40
$80
$120
$160
2012 2013 2014 2015 Budget
($M)
Frac Cost / Stage ($M)
’ ’
’
’

25. 25
Multi-Zone Well Pad Development Plan Drives Efficiency
Extensive Multi-Well Pad Experience
• 14 multi-well pads built through YE 2014
• 13 multi-well pads will be utilized in 2015
• Benefits of multi-well pad drilling
– Multi-well drilling pads allow widespread underground
development by concentrating wellheads at the surface
– Minimizes environmental impact
– Streamlines permitting process
– Eliminates mobilization time; results in ~1 additional well per
year vs. single well drilling
– Provides cost savings across all stages of development –
drilling, completions and production
Efficient Full Field Stacked Development
• 7 horizontal laterals per zone per section
• 770’ spacing between laterals
• 4 primary target pay zones
• 28 horizontal laterals per section
• North and South development from same pad

26. 26
Multi-Well Pads – Great Efficiencies Across All Stages of Development
MRD’s 4-well pads generally take ~8-9 months from spud to completion
Completion of a Multi-Well Pad Site
Vertical
Vertical Lateral
• Drilling
– Reduced location cost
– Reduced mobilization time (no rig up and rig down)
– Batch drilling of hole sections
• Completion
– More effective zipper fracs
– Continuous and efficient use of frac service contractors
– Reduces offset well shut-ins for fracs
– Cost savings from common frac water sourcing
• Production
– Cost effective comingling of production facility, pipeline,
and SWD systems
– Streamlined gas gathering and compression
Vertical
Vertical / Lateral
Lateral
LateralWell 1
Well 2
Well 3
Well 4
Illustrative Example of MRD’s Drill & Completion Schedule for a 4-Well Pad
Vertical
Vertical
Vertical
Vertical & Lateral
Lateral
Lateral
Lateral Frac
Frac
Frac
Frac

27. 27
0
200
400
600
800
1,000
1,200
Q 3 2 0 1 4 Q 4 2 0 1 4 Q 1 2 0 1 5 Q 2 2 0 1 5 Q 3 2 0 1 5 Q 4 2 0 1 5
Capacity(MMcf/d)
JT - 1 Plant Refridge - 3 Plants Cryo - 6 Plants
Secured Midstream Infrastructure Supports Development Plan
• Currently ~500 MMcf/d of available processing
capacity
• Expect to have >1 Bcf/d of processing capacity by
year-end 2015
• 3 current major gas processors
– Regency, DCP and PennTex (June 2015)
– Gather and process both low pressure and
high pressure systems
• >6 Bcf/d takeaway capacity by multiple purchasers
with no firm contracts
– No expected basis differential issues
– Processing agreements are fee based with
MRD retaining 100% of the proceeds on
residue gas and liquids
Diverse Regional TakeawaySufficient, Existing TakeawayExtensive Build Out Eliminates Potential Constraints
~1 Bcf/d of Processing Capacity Expected by Year-End 2015
~500 MMcf/d of
Processing Capacity
Currently Available
>1 Bcf/d by YE 2015
Regency
Dubach Plant
Regency
Lisbon Plant
Regency
Dubberly Plant
PennTex
Lincoln Parish Plant
PennTex
Mt. Olive Plant
DCP
Minden Plant

28. Geology
14

29. 29
Geologic Setting – Lower Cotton Valley Sands are Widespread
• Lower Cotton Valley sands were deposited over a vast area (>900 square miles) in North Louisiana
• Conventional core sample evaluation at Terryville Field confirmed shoreface depositional setting and reservoir characteristics,
which helps us understand the extent of sand development and reduces uncertainty away from the field
• Shoreface sand deposits associated with coastal shorelines, such as barrier islands, are commonly hundreds of miles in extent
– The lateral sweep of delta systems over time create expansive vertically stacked sands packages that are later trapped by shale
overburden to create oil and gas reservoirs
– Regional mapping in North Louisiana confirms this is the case for Upper and Lower Cotton Valley sands.
Modern Analog – Louisiana Coast Paleogeographic Reconstruction
Source: USGS Digital Data Series Report DDS-69-E

30. 30
North
Terryville Field Geology – Expanded Overpressured Sand
Type LogSchematic Cross Section
COTTON_VALLEY
SMACKOVER
HAYNESVILLE_LIME/SAND
BOSSIER
COTTON_VALLEY
SMACKOVER
HAYNESVILLE_LIME/SAND
BOSSIER
76770078007900800081008200830084008500860087008800890090009100920093009400950096009700980099001000010100102001030010400105001060010700108001090011000111001120011300114001150011600117001180011900120001210012200123001240012500126001270012800129001300013100132001330013400
COTTON VALLEY
BOSSIER
HAYNESVILLE
SMACKOVER
Historic vertical target
Recent vertical
commingled target
MRD Horizontal
Reservoir targets
NormallyPressuredOver-Pressured
South
Salt
• Overpressured Lower Cotton Valley sands thicken
into Terryville Field due to large growth fault
• Due to the expansive nature of the depositional
environment of the LCV sands, we believe that all
of our acreage is prospective
Terryville

31. 31
LCV Stratigraphy – Consistent Across the Terryville Field
• Four consistent, well developed Lower Cotton Valley
reservoirs proven throughout Terryville Field acreage
• Multiple target objectives
– 4 stacked target LCV reservoirs present across
entire Terryville acreage position
– All Lower Cotton Valley targets are over-pressured,
which results in higher OGIP and more reservoir
energy = higher rates and higher EUR
• Thick target intervals and broad, predictable structure
allows for drilling of ~7,500’ laterals
~10 miles
UPPER
DEEP
PINK
LOWER
DEEP
PINK
UPPER
RED
LOWER
RED
A A’
Wallace 9-1 Colvin T C 1-ALT Wright Heirs 14 2-ALT Woodland Acres 4-1
Polygon
3P
Polygon
2P
Polygon
1P
19N 5W
19N 4W
19N 3W
18N 5W 18N 4W 18N 3W
17N 5W 17N 4W 17N 3W
Claiborne
Bienville
Jackson
Lincoln
F
0
A
A’

32. 32
Continuous Focus on Well Placement – DL Sanford 18-7 HC #1
• Multi-disciplinary input to well planning
˗ Geology, Geophysics, Reservoir Engineering, Drilling,
Completions
• 24 / 7 geo-steering monitoring of all wells by all disciplines
˗ Both office and field personnel
• 2015 geo-steering performance to date: ~95% in target zone
Real-Time
Gamma Ray
Data
TARGETZONE
DL Sanford 18-17 HC 1
(IP30 29.3 MMcfe/d)
South North
Main
Structural
Fault in
North Part
of the Field

33. Reserves
14

34. 34
1,126
1,632 1,632
1,385
324
(83)
(247)
254
31
(20)
0
200
400
600
800
1,000
1,200
1,400
1,600
1,800
12/31/13 Reserves Revisions Extensions,
Discoveries and
Other Additions (incl
Enhanced Recovery)
Purchases of
Reserves
In-Place
Sales of Reserves
In-Place
Production 12/31/14 Reserves MEMP Asset Swap
(Net)
MRD PF Swap
Bcfe
Represents a
~45% Y-o-Y
increase
Expanding Reserves in the Terryville Field
Proved Reserve Growth (1)
(1) YE 2014 proved, probable and possible reserves audited by NSAI; report based on SEC pricing as of 12/31/14. YE 2013 proved reserves prepared by
NSAI and probable and possible reserves audited by NSAI; reports based on SEC pricing as of 12/31/13. See “Cautionary Statements and Additional
Disclosures” in the Appendix for more information regarding 3P reserves and PV-10
(2) Table does not give effect to the asset swap with MEMP completed in February 2015
Growth driven by strong well results and step out wells (2)
Reserves End of 2013 End of 2014 % Change
(Bcfe)
PDP 323 488 50.9%
PDNP 44 47 6.9%
PUD 758 1,097 44.7%
Total Proved 1,126 1,632 45.0%
Probable 800 904 13.0%
2P Reserves 1,926 2,537 31.7%
Possible 1,711 2,354 37.6%
3P Reserves 3,637 4,891 34.5%
PV-10 End of 2013 End of 2014 % Change
($ in millions)
PDP $610 $1,187 94.5%
PDNP 93 103 11.2%
PUD 766 1,732 126.0%
Total Proved $1,469 $3,021 105.7%
Probable 1,052 1,137 8.1%
2P Reserves $2,521 $4,158 64.9%
Possible 2,386 2,342 (1.9%)
3P Reserves $4,907 $6,500 32.5%
31

35. 35
Results Outperform Type Curves
Management Type Curves
• Updated management type curves based on
well performance, spacing and lateral length
• MRD has consistently outperformed NSAI’s
assumptions
• NSAI type curves are based on historical lateral
lengths of 4,700’ to 5,400’
• 2015 expected average lateral length >7,000’
Upper Red Lower Red Lower Deep Pink
Lateral Length (feet) 7,500’ 7,500’ 7,500’
Capex ($MM) $11.8 $11.8 $11.8
EUR (Bcfe) 20.0 13.5 9.4
EUR/1,000’ (Bcfe) 2.7 1.8 1.3
NGL Yield (Bbls/MMcf) 49 49 49
Oil Yield (Bbls/MMcf) 7.8 7.8 7.8
% Gas 71% 71% 71%
IP-30 (MMcfe/d) 28.1 23.0 20.3
IRR (%) >200% 86% 50%
PV-10 ($MM) $22.1 $11.6 $6.4
Note: Assumptions are based on $60 / Bbl oil and $3.00 / Mcf natural gas
Note: Production as of April 6, 2015. Historical average includes all wells drilled to date and represents unprocessed wellhead volumes. Average lateral length for Upper
Red, Lower Red and Lower Deep Pink are 5,381’, 5,176’, 4,755’, respectively. Data has been adjusted for shut-ins, downtime and normalized to a 7,500’ lateral length.
MRD Management PUD Assumptions
Production Continues to Outperform Type Curves
DailyProduction(MMcfe/d)
Days on Production Days on Production Days on Production
DailyProduction(MMcfe/d)
DailyProduction(MMcfe/d)
Upper Red Type Curve Lower Red Type Curve Lower Deep Pink Type Curve
0
5
10
15
20
25
30
35
0 200 400 600 800
0
5
10
15
20
25
30
35
0 200 400 600 800
0
5
10
15
20
25
30
35
0 200 400 600 800
Wells Online: 37 Wells Online: 14 Wells Online: 3
Management 7,500’ Type Curve NSAI YE14 PUD NSAI Scaled to 7,500’Historical Production Normalized to 7,500’

36. 36
NSAI Location Methodology is Conservative
Volumetric Methodology Underestimates Reserves In Place
• NSAI Upper Red PUD reserve assignment based on
~P25 distribution of producing wells, many of which are
at considerably shorter laterals (~4,500 ft) = 10.5 Bcfe
• NSAI then takes a volumetric approach:
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
0 5,000 10,000 15,000 20,000 25,000 30,000 35,000
%LessThan
NSAI Ultimate Recovery - BCFE
NSAI YE14 PDP UPPER RED EUR DISTRIBUTION
• NSAI original gas in place (OGIP) calculation for Upper
Red in 1P acreage implies ~43 Bcfe / section on
average and does not consider well spacing or lateral
length
– As a comparison, OGIP in other tight gas, overpressured
plays such as Haynesville and Utica is assumed at
100+ Bcfe / section
• In 2015, MRD plans to “break” the volumetric model,
drilling many sections at 770’ spacing and out-
producing the assumed 43 Bcfe of reserves / section
NSAI Upper Red Locations
Original Gas in Place (Bcfe) 1,525 43
x Recovery Factor (%) 70% 70%
Recoverable Gas (Bcfe) 1,068 30
Less: PDP EUR (Bcfe) (524)
PUD Reserves (Bcfe) 544
PUD Assignment per Well (Bcfe) 10.5
PUD Locations Based on EUR 52
Additional PUD Locations 29
(Based on Lower EUR Assignment)
Total NSAI PUD locations in 1P 81 2.3
Total 1P
Acreage
Average
per Section

37. 37
MRD Location Methodology
MRD Methodology - Based on Well Performance, Spacing and Lateral Length
TL McCrary / Wright Area Units
• Area depicted in blue dashed line above represents ~1,280 acres (~2 Sections)
and contains 7 producing wells, spaced between 770 and 1,000’ apart
• Average lateral length on producing wells is 4,900’
11 12
14 13
LCV RA SU I-HK
LCV RA SU
2-15H1
WRIGHT 14-11H-1
LD BARNETT 23-2H
D NOBLES 13H-1
WRIGHT 13-12HC 2
MCCRARY 14-11 HC 2
T L MCCRARY 14-11 HC 5
T L MCCRARY 14-11 HC 4ST01
WRIGHT 13-12R16
PRVUR20
TL McCrary
14-11 HC2
14.3 Bcfe
NSAI
Upper Red
PDP EURs
TL McCrary
14-11 HC5
32.9 Bcfe
TL McCrary
14-11 HC4
11.5 Bcfe
Wright 14-
11H-1
9.1 Bcfe
Wright 13-
12HC-2
23.8 Bcfe
D Nobles
13H 1
9.1 Bcfe
Wright 13-
12 HC 5
10.6 Bcfe
Total NSAI
Upper Red
PDP EURs
111.3 Bcfe
Producing
well
Management
location
7 producing wells on 2
sections have already
broken the volumetric
model
McCrary / Wright Area
(~1,280 acres / ~2 sections) (Bcfe)
Avg NSAI recoverable gas
assumption (2 sections) 60
NSAI PDP EUR 111
2 Mgmt PUD Locations EUR 40
Total Recoverable Gas 151

38. 38
MRD Location Methodology
MRD Methodology - Based on Well Performance, Spacing and Lateral Length
Colvin Estate Unit
• Shaded area depicted within unit represents ~440 acres
(~0.7 Sections) and contains 2 producing wells, spaced 770’ apart
• Average lateral length on producing wells is 8,100’
Producing
well
Drilling
29 28
32 33
5 4
A SU 53-TV
LCV RB SU A-RUS
LCV RB SU K-RUS
CV RB SUN CV RB SUO
COLVIN ESTATE 28-33 HC1
COLVIN ESTATE 28-33 HC2
TEMPLE 8-5 HC-1
BRAZZEL 29-32 HC 1
BRAZZEL_29-32_HC 4
BRAZZEL_29-32_HC 3
ZEL_29-32_HC 2
HEARNE 33-4 HC3
32-5 HC 1
8-5 HC 2
TEMPLE 8-5 HC 3
NSAI
Upper Red
PDP EURs
Total NSAI
Upper Red
PDP EURs
40.0 Bcfe
Management
location
Colvin Estate
28-33 HC1
19.97 Bcfe
Colvin Estate
28-33 HC 2
20.02 Bcfe
2 producing wells on
0.7 sections have
already broken the
volumetric model
Colvin Estate Area
(~440 acres / ~0.7 sections) (Bcfe)
Avg NSAI recoverable gas
assumption (0.7 sections) 21
NSAI PDP EUR (Bcfe) 40
2 Mgmt PUD Locations EUR 40
Total Recoverable Gas 80

39. 39
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
0 50 100 150 200 250 300 350
Producing Wells Are Greater Than NSAI PUD Type Curves
0
5,000
10,000
15,000
20,000
25,000
30,000
35,000
0 50 100 150
Colvin Estate Area Production (2 wells) vs NSAI PUD Type CurveTL McCrary / Wright Area Production (7 wells) vs NSAI PUD Type Curve
Average Lateral Length = 8,100’
Spacing = 770’
Average NSAI PDP EUR = 20.0 Bcfe
NSAI PUD Type Curve EUR = 10.5 Bcfe
Mcfe/d
Days Online
Average Lateral Length = 4,900’
Spacing = 770 - 1,000’
Average NSAI PDP EUR = 15.9 Bcfe
NSAI PUD Type Curve EUR = 10.5 Bcfe
Days Online
• When PUD reserves are converted to PDP reserves, MRD realizes a significant increase in
EUR based on well performance
• Even at tighter spacing and considerably shorter laterals, NSAI projected PDP EURs are much
greater than NSAI PUD type curve
~50% increase over
NSAI PUD Type Curve
~100% increase over
NSAI PUD Type Curve
NSAI PUD Type CurveHistorical Production

40. 40
• ~20 year drilling inventory located in MRD Upper and Lower Red
reserve categories(3)
• MRD expects management locations to continue to move into NSAI 3P
locations as well performance at 770’ spacing and empirical data
support more recoverable gas per section
• Further upside exists in Other Zones as management continues to
evaluate prospectivity in normally pressured zones across all MRD
acreage
Terryville Drilling Inventory – 35+ Year Inventory in Four Primary Zones
Terryville Future Horizontal Locations by Reserve Category (1) Distribution of Locations
403
403
418
424
CottonValley–NormallyPressuredLowerCottonValley–Overpressured
(Taylor)
(Sexton)
(Roseberry)
(Justiss)
Green
(Davis)
Vaughn
# of Locations(2)
285
1,648
(1) Does not include 35 NSAI 3P locations in the Rockies. See “Cautionary Statements and Additional Disclosures” in the Appendix for more information regarding
management locations
(2) Schedule includes additional 285 locations in Other Zones per NSAI. Does not include additional management locations located in these intervals
(3) Per MRD’s Fiscal Year 2015 Guidance for Terryville Completed Wells
Upper
Red
Lower
Red
Lower
Deep
Pink
Upper
Deep
Pink
4 Primary
Zones Total
Other
Zones
Total
MRD
Proved
NSAI 81 52 8 - 141 - 141
Management 57 8 11 - 76 - 76
Total Proved 138 60 19 - 217 - 217
Probable
NSAI 41 48 30 93 212 - 212
Management 43 38 28 7 116 - 116
Total Probable 84 86 58 100 328 - 328
Possible
NSAI 53 53 56 56 218 285 503
Management 31 57 50 51 189 - 189
Total Possible 84 110 106 107 407 285 692
Total 3P
NSAI 175 153 94 149 571 285 856
Management 131 103 89 58 381 - 381
Total 3P 306 256 183 207 952 285 1,237
Outside 3P
NSAI - - - - - - -
Management 112 168 220 196 696 - 696
Total 418 424 403 403 1,648 285 1,933

41. 41
91 141
147
212
450
503
743
1,077
0
250
500
750
1,000
1,250
1,500
1,750
2,000
2013 2014
Proved Probable Possible Management
Step-Outs Continue to Largely De-Risk the Terryville Field
Significant category shift from YE2013 (1)1P, 2P & 3P – Then and Now
~2x 1P
Acreage
(1) Includes management locations. See “Cautionary Statements and Additional Disclosures” in the Appendix for more information regarding
management locations
1,431
1,933
856 NSAI
3P
Locations688 NSAI 3P
Locations
381 Mgmt
locations in
NSAI 3P
acreage

42. Financial Overview
14

43. 43
2014 and Recent Activity
(1) Adjusted EBITDA is a non-GAAP financial measure. Please see the reconciliation to the most comparable measure calculated in accordance with GAAP in the “Appendix"
section of this presentation
(2) Excludes the effect of the asset swap with MEMP completed in February 2015. See “Cautionary Statements and Additional Disclosures” in the Appendix for more
information regarding 3P reserves and PV-10
(3) As of April 1, 2015
Solid Well Results
in 4Q and 2014
 Completed 31 horizontal wells in 2014 – 20.2 MMcfe/d IP-30
 2-well Colvin Estates pad – 50.1 MMcfe/d IP-30 (easternmost wells)
 1-well DL Sanford pad – 30.5 MMcfe/d IP-30 (northwestern-most well)
 2-well Dowling pad – 60.0 MMcfe/d IP-30 (southwestern-most wells)
 1-well LMO pad – significant step-out and increases Terryville Field delineation
Continued Positive
Results
 Increased FY14 average daily production 77% over 2013 to 227 MMcfe/d
 Increased FY14 Adjusted EBITDA(1) 74% from 2013 to $344MM
 Increased FY14 proved reserves 45% to 1.6 Tcfe and 3P reserves 34% to 4.9 Tcfe(2)
Prudent Use of
Capital
 Replaced 738% of production in 2014 from all sources
 Achieved F&D cost from all sources of $0.86 per Mcfe
 Maintained low leverage of ~1.9x debt to annualized 4Q14 EBITDA
 Current liquidity of ~$600MM
Bolt-on Acquisitions
in Terryville
 Added 20,971 gross (16,510 net)(3) acres of leasehold in the Terryville Field since IPO
through bolt-on acquisitions and active leasing program – 32% increase since IPO
 Swapped ETX assets for additional Terryville interests and $78 MM cash
Other Activities
 Hedged significant amount of production volumes at attractive pricing
 Completed $50MM share repurchase in March 2015, received approval for an additional
$50MM share purchase in April 2015
 Expect to reduce per unit operating costs significantly in 2015
 Reaffirmed borrowing base at $725MM

44. 44
Preserve Financial Flexibility
• Operate free cash flow positive asset base
• Keep leverage at conservative levels
Low Cost Operator
• Focus on low cost operations and maintaining strong
margins
• Allocate capital among projects and areas that
optimize drill-bit F&D
• Grow reserves and production by redeploying
operating cash flows into high-returning Terryville Field
Hedge to Protect Cash Flows
• Lock in commodity prices to reduce cash flow volatility
and ensure rate of return
• Protect drilling program to fund efficient production
growth
Maintain Liquidity to Support Future Growth
• Ensure ready access to the capital markets and
maintain revolver liquidity
• Robust development program supports borrowing base
growth
• Expect to fund 2015 drilling program largely from cash
flow
Financial Strategy and Capitalization
Financial Update
(1) Does not include capitalization attributable to MEMP and its subsidiaries
(2) As of March 1, 2015
(3) Adjusted EBITDA is a non-GAAP financial measure. See Appendix for more information regarding
Adjusted EBITDA, including a reconciliation of the MRD Segment Adjusted EBITDA for the three
months ended December 31, 2014
(4) Reflects market value of equity as of April 10, 2015 plus net debt
(5) Reserves audited by NSAI; report based on SEC pricing as of
12/31/14. Reserves and production are pro forma for the asset
swap with MEMP completed in February 2015.
Capitalization – MRD Segment (1)
($ in MM) 12/31/2014
Pro Forma
Cash and Cash Equivalents $5.0
Senior Secured Credit Facility
(2)
$127.0
5.875% Senior Notes due 2022 600.0
Total MRD Segment Debt $727.0
Total Stockholders' Equity $582.4
Total Capitalization $1,309.4
Operating Statistics:
4Q14 Adj. EBITDA Annualized ($MM)
(3)
$386.6
Enterprise Value ($MM)
(4)
4,089.7
Proved Reserves (Bcfe)
(5)
1,384.7
4Q14 Production (MMcfe/d)
(5)
260.1
Credit Statistics:
Borrowing Base $725.0
Less: Outstanding Borrowings ($127.0)
Plus: Cash $5.0
Liquidity $603.0
Total Debt /
4Q14 Adj. EBITDA Annualized (x) 1.9x
Enterprise Value (%) 18%
Proved Reserves ($/Mcfe) $0.53
4Q14 Production ($/Mcfe/d) $2,795.1

45. 45
2015 FY Guidance
Low High
Net Average Daily Production (MMcfe/d) 325 - 365
Natural Gas (MMcf/d) 240 - 270
NGLs (Bbls/d) 10,900 - 12,300
Oil (Bbls/d) 3,200 - 3,600
Average Costs (per Mcfe)
Lease Operating ($0.20) - ($0.15)
Production and Ad Valorem Taxes
(1)
($0.15) - ($0.10)
Cash General and Administrative ($0.30) - ($0.25)
Commodity Price Realizations (Unhedged)
(2)
Gathering, Processing and Transportation ($0.70) - ($0.55)
and BTU Adjustment ($/Mcfe)
(3)
Natural Gas Realized Price (% of NYMEX to Henry Hub)
(4)
95% - 100%
NGL Realized Price (% of WTI NYMEX) 30% - 35%
Crude Oil Realized Price (% of WTI NYMEX) 95% - 100%
Drilling Program
Terryville Field Wells Spud (Gross) 55 - 60
Terryville Field Wells Completed (Gross) 40 - 45
Terryville Field D&C Capital Expenditure ($MM) $475 - $525
Fiscal Year 2015 Guidance
Detailed Guidance
• FY15 total D&C capital
expenditures of ~$500MM
• 2015 daily production projected to
average between 325 - 365
MMcfe/d
– >50% FY YOY increase
– >70% PF YOY increase for
East Texas divestiture
• Budget supported by 8 horizontal
drilling rigs in 2015
– All located in the Terryville Field
– Compares to 4 rigs at year-end 2013
Note: Guidance as of February 24, 2015
(1) Amount varies based on abatement credits from newer horizontal wells
(2) Based on strip pricing as of February 13, 2015
(3) Gathering, processing and transportation costs are treated as a deduction from revenue on MRD’s income statement
(4) Does not include gathering, processing and transportation costs
Highlights

46. 46
2015E YOY Production Growth (4)
79% 77%
74%
56%
48%
40%
24%
4% 3%
-10%
-21%-30%
-20%
-10%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
ECR REXX MRD RICE RSPP PDCE AR BCEI JONE CRZO CWEI GDP
MRD Peer Comparison
Q4 2014 Debt / EBITDA (3)
• Historical LOE Expense ($/Mcfe)
4.9 x 4.8 x
3.8 x
3.5 x 3.4 x
2.6 x 2.5 x 2.4 x 2.3 x 2.2 x
1.9 x
0.0 x
1.0 x
2.0 x
3.0 x
4.0 x
5.0 x
6.0 x
7.0 x
ECR GDP PDCE REXX RICE AR JONE CRZO CWB RSPP BCEI MRD
$1.01
$0.74
$0.50
$0.32
$0.18
$0.00
$0.40
$0.80
$1.20
2011 2012 2013 2014 2015E
Source: Company filings. Note: All averages exclude MRD
Note: Averages exclude MRD
(1) Other expenses includes lease operating expenses, production taxes, ad valorem taxes and gathering and processing fees where applicable
(2) Excludes $0.06 / Mcfe of expenses associated with long-term incentive plan and acquisition-related costs
(3) Adjusted EBITDA is a non-GAAP financial measure. Please see the Appendix for more information regarding MRD’s Adjusted EBITDA, including the reconciliation to the most
comparable measure calculated in accordance with GAAP
(4) Gives effect to the asset swap with MEMP completed in February 2015
10.0x
Average: 3.9x
Average: 30%
MRD Historical LOE Expense ($/Mcfe) 2014 FY Total Cash Cost ($/Mcfe)
NA
(1)
(2)
$0.21 $0.45 $0.43
$0.11 $0.37 $0.33 $0.28
$0.96
$1.72
$0.28
$0.49 $0.71 $1.08
$1.53 $1.60 $1.85
$1.93
$3.36
$0.49
$0.94
$1.14 $1.19
$1.91 $1.94
$2.14
$2.89
$5.08
Average $2.10
--
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
$7.00
EQT MRD RICE COG RRC GPOR AR GDP MHR
Cash G&A Other Expenses

47. 47
Ethane
33%
Ethane
33%
Propane
21%
Propane
35%
N Butane
9%
N Butane
9%
Isobutane
8%
Isobutane
9%
Pentane
29%
Pentane
14%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Terryville Average Company
37% 36% 39%
50%
50%
55% 44% 42%
51%
57%
57%
64%
63%
64%
61%
50%
50%
45%
56% 58%
49%
43%
43%
36%
$0
$10
$20
$30
$40
$50
$60
$70
$80
$90
$100
1Q122Q12 3Q12 4Q121Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14
Revenue(Terryville)
Gas Oil & NGLs
Rich NGLs Drive Strong Economics
MRD’s NGL Barrel is Heavy
(1) (2)
(1) Barrel composition is before hedges and represents our Terryville field production for September 2014
(2) Based on Wall Street research for 2015E for North America
46% 32%
($MM)
Current realized NGL pricing is ~39%
of WTI due to high concentration of C-5
20
Liquids Provide ~36% of Revenues

48. 48
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
$5.00
$60 Oil / $3.00 Natural
Gas
$50 Oil / $2.50 Natural
Gas
$30 Oil / $2.00 Natural
Gas
$10 Oil / $1.00 Natural
Gas
$/Mcfe
Realized Price Hedge Revenue
Hedges Help Protect 2015 Revenue
Hedging Impact on 2015 Revenue
Only ~11%
change in
total realized
price due to
robust hedge
support
Significant hedge book allows MRD to have minimal revenue change even in draconian price
environment
23%
77%
50%
77%
23%
Note: Production and per unit realized prices based on mid-point of 2015 Guidance; realized hedges calculated on flat prices of $60 oil / $3.00 natural gas, $50 oil / $2.50 natural
gas, $30 oil / $2.00 natural gas and $10 oil / $1.00 natural gas respectively
Total Realized
Price = $4.42
Total Realized
Price = $4.32
Total Realized
Price = $4.15
34%
66%
50%
50%
Total Realized
Price = $3.95

49. 49
Robust Cash Margins in all Price Environments
Low per unit costs and attractive hedge positions provide strong cash margins
20
67%
Cash
Margin 64%
Cash
Margin
Total Realized
Price = $4.62 Total Realized
Price = $4.42
63%
Cash
Margin
65%
Cash
Margin
Total Realized
Price = $4.32 Total Realized
Price = $4.15
$-
$0.50
$1.00
$1.50
$2.00
$2.50
$3.00
$3.50
$4.00
$4.50
$5.00
$80 Oil / $4.00
Natural Gas
$60 Oil / $3.00
Natural Gas
$50 Oil / $2.50
Natural Gas
$30 Oil / $2.00
Natural Gas
Gath, Proc, Trans
LOE
Production Taxes
Cash G&A
Cash Interest
Realized Hedges
Cash Margin from O&G Revenue
$/Mcfe
Note: Production and per unit costs based on mid-point of 2015 Guidance; realized hedges calculated on flat prices of $80 oil / $4.00 natural gas, $60 oil / $3.00
natural gas, $50 oil / $2.50 natural gas and $30 oil / $2.00 natural gas respectively

50. 50
0% 0% 0%
22%
24%
41%
45%
53%
58%
70%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
RSPP COG FANG EQT RRC RICE AR JONE MRD PE
% Hedged
MRD Has an Attractive Hedge Portfolio
26%
37% 37%
52%
58%
65%
78%
88% 90%
94%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
COG FANG RSPP EQT RRC PE MRD RICE JONE AR
% Hedged
Median: 62%
Percent of Total Production Hedged(1)
On a relative basis, MRD has larger hedge volumes and a longer dated hedge book than its peers
(1) Based on Wall Street Research estimates for future production. 2016E production is held flat due to lack of research for 2017E and 2018E
2015 2016
Median: 32%
0% 0% 0% 0% 0% 0% 0%
25%
49%
51%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
RSPP COG FANG EQT RRC RICE PE JONE MRD AR
% Hedged
0% 0% 0% 0% 0% 0%
8%
33%
37%
41%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
RSPP COG FANG EQT RRC RICE PE JONE AR MRD
% Hedged
Median: 0%
2017 2018
Median: 0%

51. 51
Hedge Summary
Year Ending December 31,
2015 2016 2017 2018
Natural Gas Derivative Contracts:
Total natural gas volumes hedged (MMBtu) 81,960,000 93,240,000 75,240,000 89,400,000
Total weighted-average price $3.97 $3.95 $4.02 $3.94
Percent of mid-point guidance 88.1%
Crude Oil Derivative Contracts:
Total crude oil volumes hedged (Bbl) 894,000 426,000 336,000 379,500
Total weighted-average price $89.38 $88.64 $84.70 $84.50
Percent of mid-point guidance 72.0%
Natural Gas Liquids Derivative Contracts:
Total natural gas liquids volumes hedged (Bbl) 1,812,000 2,227,895 – –
Total weighted-average price $41.61 $34.06 – –
Percent of mid-point guidance 42.8%
Total Derivative Contracts:
Total Hedged Production (MMBtue) 98,196,000 109,163,371 77,256,000 91,677,000
Total weighted-average price $4.90 $4.41 $4.28 $4.19
Percent of mid-point guidance 78.0%
MRD Hedging Overview: 2015 through 2018
• MRD’s commodity risk management policy provides for hedging estimated production from
total proved reserves
– Proactive policy reduces MRD’s exposure to movements in commodity prices and
provides stability to cash flow
– All of MRD’s trading counterparties have investment grade credit ratings
– MRD’s current hedges include fixed price swaps, collars and deferred premium puts and
calls
35

52. 52
Investment Highlights
35
Best-in-Class Assets with Top Tier Growth
Premier Drilling Economics with Extensive Inventory
Funding Growth Predominately with Internally Generated Cash Flow Coupled with a
Conservative Balance Sheet
Secured Infrastructure Supports Growth Plans
Experienced Management Team with Extensive Knowledge of the Cotton Valley

53. Appendix

54. 54
As of December 31, 2014 As of April 1, 2015
Gross Net Gross Net
Terryville Field 73,738 61,157 81,012 68,032
Other Louisiana 49,198 44,291 27,772 25,300
Total Louisiana Acres 122,936 105,448 108,784 93,332
Significant and Growing Acreage Position
• 703 wells
– 586 operated
– 117 non-operated
• 10 salt water disposal wells
MRD continues to pursue attractive bolt-on acreage in and around the
Terryville Field where MRD believes it has the ability, local knowledge and
resources to add to MRD’s already significant position
Current Land Statistics for MRD’s Louisiana Assets(1) (2)
• 621 working interest owners
• 8,532 revenue owners
• 7 parishes
(1) Includes “Terryville Field” and “Other Louisiana”
(2) Gives effect to the asset swap with MEMP completed in February 2015 and does not include MRD’s Rockies acreage
Louisiana Acreage Details(1) (2)

55. 55
Organizational Chart & Ownership(1)
Certain Former
Management Members of
WildHorse Resources
MRD Holdco LLC
Memorial Resource
Development Corp.
(NASDAQ: MRD)
Memorial Production
Partners GP LLC
General Partner Units
Incentive Distribution Rights
MRD Operating LLC
(Terryville Complex)
Memorial Production
Partners LP
(NASDAQ: MEMP)
NGP Funds
Public
Public
18% 39% 43%
0.1% GP interest
50% IDR interest
6.2% limited
partner interest
93.7% limited partner interest
(81.3MM common units)
9
Headquarters: Houston, TX
Employees: ~500 full-time
(1) As of March 17, 2015
100%

56. 56
MRD NSAI Reserve Detail
(1) Proved, probable and possible reserves audited by NSAI; report based on SEC pricing as of 12/31/14. See “Cautionary Statements and Additional Disclosures”
in the Appendix for more information regarding 3P reserves and PV-10
(2) Proved reserves are engineered by NSAI as of December 31, 2013; probable and possible reserves prepared by MRD and audited by NSAI; reports based on
SEC pricing as of 12/31/13. See “Cautionary Statements and Additional Disclosures” in the Appendix for more information regarding 3P reserves and PV-10
2014(1)2013(2)
Oil
(MBbl)
Natural Gas
(MMcf)
NGLs
(MBbl)
Total
(MMcfe)
% Gas
(%)
PV-10
($M)
PDP 3,290 358,795 18,211 487,800 74% 1,186,884$
PDNP 615 33,386 1,713 47,351 71% 102,958
PUD 8,698 788,748 42,665 1,096,928 72% 1,731,506
Total Proved 12,603 1,180,929 62,589 1,632,079 72% 3,021,348$
Probable 8,448 610,363 40,570 904,470 67% 1,137,039
2P Reserves 21,051 1,791,291 103,159 2,536,548 71% 4,158,388$
Possible 35,765 1,595,662 90,668 2,354,260 68% 2,341,832
3P Reserves 56,816 3,386,953 193,826 4,890,809 69% 6,500,219$
Oil
(MBbl)
Natural Gas
(MMcf)
NGLs
(MBbl)
Total
(MMcfe)
% Gas
(%)
PV-10
($M)
PDP 2,626 234,037 12,260 323,351 72% 610,304$
PDNP 777 29,760 1,645 44,290 67% 92,615
PUD 7,908 538,457 28,672 757,936 71% 766,033
Total Proved 11,311 802,254 42,577 1,125,577 71% 1,468,952$
Probable 10,480 535,185 33,709 800,317 67% 1,052,243
2P Reserves 21,790 1,337,440 76,285 1,925,894 69% 2,521,195$
Possible 36,376 1,080,540 68,686 1,710,914 63% 2,386,228
3P Reserves 58,166 2,417,980 144,972 3,636,808 66% 4,907,423$

57. 57
Adjusted EBITDA Reconciliation
Adjusted EBITDA is a non-GAAP financial measure. We evaluate segment performance based on Adjusted EBITDA. Adjusted
EBITDA is defined as net income (loss), plus interest expense; debt extinguishment costs; income tax expense; depreciation, depletion
and amortization; impairment of goodwill and long-lived properties; accretion of asset retirement obligations; losses on commodity
derivative contracts and cash settlements received; losses on sale of properties; stock-based compensation; incentive-based
compensation expenses; exploration costs; provision for environmental remediation; equity loss from MEMP; cash distributions from
MEMP; acquisition related costs; amortization of investment premium; and other non-routine items, less interest income; income tax
benefit; gains on commodity derivative contracts and cash settlements paid; equity income from MEMP; gains on sale of assets and
other non-routine items.
MRD’s non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income, operating
income, net cash flows provided by operating activities or any other measure of financial performance calculated and presented in
accordance with GAAP. MRD's non-GAAP financial measures may not be comparable to similarly-titled measures of other companies
because they may not calculate such measures in the same manner as MRD does.
The following table presents the MRD Segment information for the periods indicated:
For the Three Months For the Year Ended
Ended December 31, December 31,
(Amounts in $000s) 2014 2013 2014 2013
MRD Segment net income (loss) 167,223$ (32,385)$ (762,926)$ 82,243$
Add (Deduct):
Interest expense, net 5,928 11,402 50,283 27,349
Debt extinguishment costs - - 37,248 -
Income tax expense 85,527 164 99,850 1,311
Depreciation, depletion and amortization 47,421 24,438 154,917 87,043
Impairment of proved oil and gas properties 24,576 2,527 24,576 2,527
Accretion of asset retirement obligations 193 181 688 728
(Gains) losses on commodity derivatives (240,604) 5,348 (257,734) (3,013)
Cash settlements received (paid) on commodity derivatives 14,096 3,115 9,166 12,240
Acquisition related costs 737 (67) 2,305 1,584
Stock-based compensation (LTIPs) 1,317 - 2,804 -
Incentive-based unit compensation expenses (25,441) 24,210 943,949 43,279
(Gain) loss on sale of properties - 597 3,057 (82,773)
Loss on office lease 1,180 - 1,180 -
Exploration costs 14,600 89 15,813 1,226
Equity (income) loss in MEMP (188) (2,301) 12,656 (1,847)
Cash distributions from MEMP 76 6,906 6,144 26,006
MRD Segment Adjusted EBITDA: 96,641$ 44,224$ 343,976$ 197,903$

58. 58
Adjusted Net Income Reconciliation
MRD Segment Adjusted Net Income is a supplemental non-GAAP financial measure that is used by external users of MRD’s financial
statements. We define MRD Segment Adjusted Net Income as net income excluding the impact of certain items including gains or
losses on commodity derivative instruments not yet settled, gains or losses on sales of properties, debt extinguishment costs, equity
income in MEMP, stock-based compensation and incentive-unit compensation expense. We believe MRD Segment Adjusted Net
Income is useful to investors because it provides readers with a more meaningful measure of our profitability before recording certain
items for which the timing or amount cannot be reasonably determined. However, this measure is provided in addition to, not as an
alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance
with GAAP.
The following table presents the MRD Segment information for the periods indicated:
For the Three Months For the Year Ended
Ended December 31, December 31,
(Amounts in $000s) 2014 2013 2014 2013
MRD Segment net income (loss) 167,223$ (32,385)$ (762,926)$ 82,243$
Add (Deduct):
(Gains) losses on commodity derivatives (240,604) 5,348 (257,734) (3,013)
Cash settlements (paid) received on commodity derivatives 14,096 3,115 9,166 12,240
(Gain) loss on sale of properties - 597 3,057 (82,773)
Stock-based compensation (LTIPs) 1,317 - 2,804 -
Incentive-based compensation expenses (25,441) 24,210 943,949 43,279
Equity (income) loss in MEMP (188) (2,301) 12,656 (1,847)
Debt extinguishment costs - - 37,248 -
Tax effect of adjustments 85,437 - 94,885 -
MRD Segment Adjusted Net Income (Loss) 1,840$ (1,416)$ 83,105$ 50,129$

59. 59
Cautionary Statements and Additional Disclosures
Except as otherwise indicated, the description of MRD’s business, properties, strategies and other information in this presentation relates solely to the
MRD Segment, which excludes the business, properties, strategies and other information regarding Memorial Production Partners LP.
This presentation has been prepared by MRD and includes market data and other statistical information from sources believed by MRD to be reliable, including
independent industry publications, government publications or other published independent sources. Some data is also based on MRD’s good faith estimates, which
are derived from its review of internal sources as well as the independent sources described herein. Although MRD believes these sources are reliable, it has not
independently verified the information and cannot guarantee its accuracy and completeness.
3P Reserves and PV-10
MRD has disclosed PV-10 in this presentation based on its reserve reports. PV-10 is a non-GAAP financial measure and represents the period-end present value of
estimated future cash inflows from our natural gas and crude oil reserves, less future development and production costs, discounted at 10% per annum to reflect
timing of future cash flows and using SEC pricing assumptions in effect at the end of the period. SEC pricing for natural gas and oil of $3.67 per MMBtu and $93.42
per Bbl and $4.35 per MMBtu and $91.48 per Bbl was based on the unweighted average of the first-day-of-the-month prices for each of the twelve months preceding
December 2013 and December 2014, respectively. PV-10 differs from standardized measure, the most directly comparable GAAP financial measure, because it does
not include the effects of income taxes. Moreover, GAAP does not provide a measure of estimated future net cash flows for reserves other than proved reserves.
Because PV-10 estimates of probable and possible reserves are more uncertain than PV-10 and standardized estimates of proved reserves, but have not been
adjusted for risk due to that uncertainty, they may not be comparable with each other. Nonetheless, MRD believes that PV-10 estimates for reserve categories other
than proved present useful information for investors about the future net cash flows of its reserves in the absence of a comparable GAAP measure such as
standardized measure. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from
proved reserves on a more comparable basis. In addition, investors should be cautioned that estimates of PV-10 for probable and possible reserves, as well as the
underlying volumetric estimates, are inherently more uncertain of being recovered and realized than comparable measures for proved reserves, and that the
uncertainty for possible reserves is even more significant. MRD’s PV-10 estimates of proved reserves and its standardized measure for 2013 are equivalent because,
prior to its initial public offering, MRD was not subject to entity level taxation. For 2014, MRD has included a reconciliation of the estimate of PV-10 for proved
reserves to the most directly comparable GAAP measure, standardized measure, at the end of this Appendix. Neither PV-10 nor standardized measure represents an
estimate of fair market value of MRD’s natural gas and oil properties. MRD and others in the industry use PV-10 as a measure to compare the relative size and value
of estimated reserves held by companies without regard to the specific tax characteristics of such entities.
We have provided summations of our proved, probable and possible reserves and summations of our PV-10 for our proved, probable and possible reserves in this
presentation. The SEC strictly prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of
certainty associated with each reserve category. Investors should be cautioned that estimates of PV-10 of probable reserves, as well as the underlying volumetric
estimates, are inherently more uncertain of being recovered and realized than comparable measures for proved reserves, and that the uncertainty for possible
reserves is even more significant. Further, because estimates of probable and possible reserve volumes and PV-10 have not been adjusted for risk due to this
uncertainty of recovery, their summation may be of limited use. Investors are cautioned to review any such summations together with the breakdown of our reserves
by category as set forth in this presentation.

60. 60
Cautionary Statements and Additional Disclosures
Hydrocarbon Quantities
The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable, and possible reserves that meet the SEC’s definitions for such
terms. We may use certain broader terms such as EUR (estimated ultimate recovery), and we may use other descriptions of volumes of potentially recoverable
hydrocarbon resources throughout this presentation that the SEC does not permit to be included in SEC filings. Within this presentation, when referring to a currently
producing well, EUR refers to the sum of total gross remaining proved reserves attributable to each location in the applicable MRD reserve report and cumulative
sales from such location. You should not assume that such terms or descriptions are comparable to proved, probable or possible reserves or represent estimates of
future production from properties. Estimates of quantities of oil and gas that use such terms or descriptions, such as EURs, are by their nature more speculative than
estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized, particularly in areas or zones
where there has been limited or no drilling history. MRD uses these estimates to demonstrate what MRD believes to be the potential for future drilling and production
by MRD. Actual locations drilled and quantities that may be ultimately recovered from MRD’s properties may differ substantially from the estimates used in this
presentation. Ultimate recoveries will be dependent upon numerous factors such as the scope of MRD’s ongoing drilling program, actual drilling results, including
geological and mechanical factors affecting recovery rates, the impact of future commodity pricing, the availability of capital, drilling and production costs, budgets
based upon MRD’s future evaluation of risk and returns, availability of drilling services and equipment, lease expirations, transportation constraints, regulatory
approvals and other factors.
Management Locations
MRD has disclosed gross horizontal drilling locations in this presentation in the proved, probable, and possible categories as audited by NSAI, MRD’s third party
engineers, as well as 1,077 drilling locations that have been identified by MRD’s management. MRD identified those additional locations using the same methodology
as those locations to which probable and possible reserves are attributed—by using existing geologic and engineering data from vertical production and seismic data.
Of those 1,077 gross horizontal drilling locations, 381 lie within the geographic areas to which proved, probable and possible reserves are attributed and are based on
assumed well spacing of 137 acres. The remaining 696 management identified gross horizontal drilling locations, all of which are also based upon 137-acre spacing,
are within geographic areas to which proved, probable or possible reserves are not attributed, but nonetheless are locations that MRD has specifically identified based
on its evaluation of applicable geologic and engineering data accrued over our multi-year historical drilling activities in the surrounding area. The locations on which
MRD actually drills wells will ultimately depend upon the availability of capital, regulatory approvals, seasonal restrictions, oil and natural gas prices, costs, actual
drilling results and other factors, and may differ from the locations currently identified.
IRR Calculation
MRD’s estimates of projected IRR were calculated using the following assumptions:
• Terryville IRRs based on MRD internal estimates with a flat crude oil prices of $50.00, $60.00, $70.00 and $80.00 per barrel and flat natural gas price of $2.50,
$3.00, $3.50 and $4.00 per MMBtu
• MRD internal estimates assume 7,500 foot lateral length; terminal decline of 10%; 100% working interest / 78% net revenue interest; lease operating costs and
production taxes from existing wells and well cost of ~$11.8MM

61. 61
Reconciliation of PV-10 to Standardized Measure
PV-10 is a non-GAAP financial measure and differs from the standardized measure of discounted future net cash flows, which is the
most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash
flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before
deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors
because it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account
future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas
properties. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other
companies without regard to the specific tax characteristics of such entities. We use this measure when assessing the potential return
on investment related to our oil and natural gas properties. PV-10, however, is not a substitute for the standardized measure of
discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport
to represent the fair value of our oil and natural gas reserves.
The following table provides a reconciliation of PV-10 of our proved reserves to the standardized measure of discounted future net cash
flows at December 31, 2014, 2013 and 2012:
Prior to our initial public offering, we were not subject to federal income tax; hence no income taxes were applied to reserve values in
previous years.
For the Year Ending December 31,
2014 2013 2012
(In thousands)
PV-10 $ 3,021,348 $ 1,468,952 $ 1,320,595
Less: present value of future income taxes discounted at 10% 1,058,814 — —
Standardized measure $ 1,962,534 $ 1,468,952 $ 1,320,595